Multistage hydrafracturing process and apparatus



J. U Q m CROSS REFEQEN CE SEARCH ROW March 8, 1960 J. E. HALL, SR2,927,638

- MULTISTAGE HYDRAFRACTURING PROCESS AND APPARATUS Filed Jan. 10, 1955'7 Sheets$heet 1 VENTOR. Jesse flal 5/:

' March 8, 1960 J. E. HALL, SR 2,927,638

MULTISTAGE HYDRAF'RACTURING PROCESS AND APPARATUS Filed Jan. 10, 1955 7Sheets-Sheet 2 a 5 z z z INVENTOR. Jifi' 5 #4/4 5/:

March 8, 1960 v J. E. HALL, SR 2,927,633

I MULTISTAGE HYDRAFRACTURING PROCESS AND APPARATUS Filed Jan. 1 0, 19557 Sheets-Sheet 4 1 I I 3 4 E 1 .10 x INVENTOR. fl Je55e 5 194/; 5/:

ATTORNEK March 8, 1960 J. E. HALL, SR 2,927,533

MULTISTAGE HYDRAFRACTURING PROCESS AND APPARATUS 7 Sheets-Sheet 5 FiledJan. 10, 1955 1 w m .mwJm fig! lw w n F, w

Y a B A iii:

MULTISTAGE HYDRAFRACTURING PROCESS AND APPARATUS Filed Jan. 10, 1955March 8, 1960 J. E. HALL, SR

'7 Sheets-Sheet 6 a .w/ m a 412 ww f w wfi fl j w M x HYDRAFRACTURINGPROCESS AND APPARATUS MULTISTAGE This invention relates to improvementsin the fracturing of the earth formation surrounding wells and relatesmore particularly 'to a process of increasing the productivity of wellsby increasing the number and size of lateral drainage channels in theproducing formations adjacent the well bore. In this art of increasingsuch lateral channels, it is conventional to pump into selectedformations surrounding the well bore fluids and mixtures of fluids andsolids under high pressure and this practice is utilized in the processhereinafter disclosed.

The instant process, however, differs from what has previously, beendone in thata relatively narrow zone is selected and sealed off by meansof packers with ports or apertures penetrating the casing within saidzone. The area of these ports bears a predetermined relationship to thecross-sectional areaof the tubing through which the fracturing liquidissupplied to'assu're high velocity and reduce th'e likelihood ofobstructing or clogging the fluid passageways. In addition, the processis unique in that successive fracturing operations are performed whilemaintaining the system pressure-tight and under a closed-in pressure notsubstantially below pressures imposed during circulation. In otherwords, it is unnecessary to delay consecutive fracturing operationsuntil the high pressure imposed during each fracturing operationsubsides or is reduced sufliciently to move the sealing devices toanother location without backflow of fracturing liquid and theaccompanying difficulties associated therewith. I u 7 An object of theinvention, therefore, is to provide a process and apparatus wherebysuccessive formation 0 packet shown in Fig. .1c.

Fig. lb showsthe pressure retainer and a portion of the well bore incross section located immediately below the lower end of the tubingshown in Fig. 1a. 7 t

Fig. 1c is an extension of Fig. 1b showing a portion of the well bore incross section and packers used for sealing. off a zone tobe fractured.

Fig. 2 is an enlarged cross-sectional detail of the pressureretainershown in Fig. 1b.

Fig. 3 is an enlarged cross 'sectinal detail of the lower Fig. 4115aview taken along the line in the direction of the arrows.

Fig. 5 is a view taken along the in the direction of the arrows.

Fig. 6 is an enlarged cross section of the well bore shown below thelowerbroken-away section in Fig. 1b.

4% i in Fig.2

line s -s in Fig. 2

Fig. 7 is a view taken along the line 7'-7 in Fig. 1a

' mechanism.

fracturing operations may be performed while maintain? ing a closed-inpressure and without the necessityof the delays now necessary underpresent operating technique.

Another object is to provide a system in which successive thin or narrowzones of the well bore are isolated in successive operations" andfractured consecutively in a relatively continuous cycle of operations.

A further object resides in maintaining a predetermined relationshipbetween the cross-sectional area of the tubing and the area of the portsthrough which the fracturing fluid is introduced to the formation.

Still other objects include the provision of a pressureretainingmechanism permitting the vertical movement of the tubing in the casingwhile maintaining a closed-in pressure and back pressure valvesstrategically positioned in the tubing which permit removing sections ofthe tubing at the surface without loss of system pressure.

. a 0 fracturing fluid, 7

Fig. 11 is a cross-sectional view of a well bore showing that portion ofthe tubing string immediately above that shown in Fig. 10. V

Fig. 12 is an enlarged cross-sectional detail of the circulatingvalve'mechanism shown diagrammatically in Fig. 10. a

Fig. 13 is an enlarged cross-sectional detail of a portion of thecirculating valve mechanism shown in Fig. 12.

Fig. 14 is a sectional view taken along the line -1414 in Fig. 12 in thedirection of the arrows. I v

Fig. 15 isa view taken along the line 15-15 in Fig. 10 in the directionof the arrows.

Fig. 16 is an enlarged exploded view of thepacker arming'device. a I vFig. 17 is a vertical section of a modified type of pressure retainerfrom that shown in Fig. 2.

Fig. 18 is an enlarged horizontal section taken'along the line 18ll8 inFig 17 in the direction of the arrows.

Fig. 19 is an enlarged horizontal section taken along the line 19 1) inFig. 17 in the direction of the ar !OWS.

Fig. 20 is an enlarged sectional perspective view of the segmentalanti-extrusion device.

Fig. 21 is an elevational view of a modified type of packer operatingmechanism.

' Fig. 22 is an enlarged vertical section taken along the line 22-22 inFig. 21.

Fig. 23 is an enlarged sectional view taken along the line 23-23 in'Fig.21.

Referring to the drawings and particularly to Figs. 1a, 1b, 1c and 6,after the well bore has been drilled through earth formations indicatedgenerally at- 10, a casing 11 is run in the hole upon which are mounted,at intervals throughout the well bore where cement is to be placed,centralizers 12 and scratchers 13. After the annulus between the casingand well wall has been cleaned of mud deposited during the drillingoperation, a cement column 14 is placed in the well bore surroundingthe' During. the drilling of the well, conventional testing.

methods, suchas caliper logging, for determining the hpa'r'pas size ofthe well bore at diife of logging for locating the position of perviousand impervious layers is good practice. After the cement has beenplaced, temperature logging, gamma ray logging and other electroniclogging methods are useful to deter mine the'charact er andefiectiveness of the cement column and to establish locations forshooting the casing and cementcolumn for best results in producing fluidoil from the in producing sands. After locating the per meablehorizonsor suspected oil'sands, the well is shot at a plurality ofdepths in each sand,.pref erably six to eight holes will he made intotheformation at each zone rent depths and other methods to be f ractured.The number of holes is "determined by the -relationship thecross-sectional] arealof the tubing bears tothe area of the holesshot ineach fracturing zone. Anticipating fracturing of the siispected oilproducing formation in thin or narrow'zones', the number and size of theholes in the zone to befractured is limited in order to assure highvelocity of the fluid through the ports or.

holes when fracturing pressure is imposed.v Normally,

the cross-sectional area of the holes or ports located in the fracturingzone is considerably less than the cross sectional area of the tubing,so passage of the fracturing liquid downwardly through the tubing andlaterally into the formation through the apertures shot in the casingwill be at increased velocity with respect to the flow of oil throughthe tubing. Obviously the spacing of the holes 1 or apertures verticallyin the oil sand and the number and size of the holes made at thedilferentlevels is an impor tant factor when thin or narrow zonefracturing is practiced, The manner in which the suspected oil producingzones'is tobe shot is shown diagrammatically in Fig. 1c,

the apertures or ports'through the casing andcement column beingindicated by the numerals 16. 1

After the suspected production formations have been perforated byshooting as explained, a tubing 17 with suitable sealing devices orpackers properly located on the tubing to seal the annulus between thetubing and easing above and below the selected zone to be fractured isrun into the well. Packers used in the instant process are of improveddesign; their construction is shown diagrammatically in Figs. 1c,l0,11,',and in detail in Figs. 3, Hand 21. Structurally the packer shownin Figs. 1c and 3 includes resilient sealing members 18 reinforced attheir outer edges with metal coils 18a embedded and i utimately bondedinto the resilient material. The inner surface or core of the sealingmembers are-reinforced by cylindrical metallic sleeves 19 shown best inFig. 3. These sleeves and coil spring reinforcement serve to preventflowing of the resilient material under the high pressures andtemperatures to which packers are subjected. At thebottom of the lowerpacker and at the top of the upper packer are radial slips operatingwithin annular closures 20 which are bored and threaded to receivecylinders 21. Operating within these cylinders are piston slips22 whoseoutward movement is restricted by lips 21a (Fig. 9) at the outer ends ofthe cylinders'abutting shoulders on the pistons. Retaining strips 23attached to the periphery of enclosure 2% and resting in longitudinalgrooves in the top of the pistons, details of which are best shown inFigs. 3 and 9, also serve to limit outward movement of ,the pistons.Retaining rings 24 screwed into the inner ends ofthe cylinders limit theinward movement of the pistons. A knurledor roughened surface at theends of the piston seat against the smooth inner surface of the casingto hold the packer rigidly against longitudinal movement in the casing.

- Packersleeve 25 isthreaded internally at its upper and lower ends toreceive rings 26 and 27. The sleeve 25 and closure rings 26 and 27 forma pressure annulus or compartment around the exterior of the tubing withcom munication to'the tubing by means of holes 28. Within the pressureannulus is a. ring 35? which is screwed onto theext'criorof the tubingor mandrel and on the exterior of'ring 30 is threaded a stop seal ring31 upon whichis' mounted compression spring 29. In the tubing or-mandrel17 above the lower packer and below the upper packer are a series ofports or apertures 32 through which fluid under pressure is supplied tothe annular space between the packers, thence'to the formation to befractured. Connecting the sections of tubing are couplings 33 whoseoutside diameter is somewhat larger than the outside diameter of thetubing. 7 I

At selected locations along the tubing are interposed back pressurevalves 330 shown in Fig. 1a and Fig. 7. The position of these-backpressure valves along the tubing is determined by the location of thesuspected production zones'or the'zones to be fractured. The purpose ofthe valves is to hold pressure in-the system while sections of thetubing are removed above the ground surface. The structural details ofthe valves shown in Figs. 7 and 8 include a body 33a having an upperinternally threaded portion to screw onto themale end of the tubing. Thelower end of the body is externally threaded to receive a union 34 whichconnects the body to the next adjacent section of tubing below, or inplace of the union, the lower end of the body may be screwed directlyonto an internally threaded end of the tubing'section immediately below.Within the ,body 33a is a cavity in which a ball valve 35'is supportedupon webs or fins 36. When supportedupon fins the valve is held in anopen position: bymeans ofa set screw 37. Upon backing off the set screw37, the ball valve is free to seat upwardly against the beveled-ring 38and serves as an effective seal against passage of'fluid upwardlythrough the tubing; Normally, during fracturing operation the set screwis in position shown in Fig. 7 with. the ball held on the low ered,position permitting free passage. of fluid in either direction throughthe tubing. e

"Mounted-above'ground at the top of the casing is a pressure retainermechanism 39 shown in Figs. 1b and 2. The pressure retainer serving some.of the functions of a blow-out preventer comprises a shell or casing 40externally threaded at its ends to receive sleeves 41 and 42. Within thesleeves are resilient annularrings 43 and 44 reinforced at the top andbottom internally by means of coil springs 45,. Abutting the top ofresilient member 43 and screwed into the topof the sleeve is a closurering 46, while against the lower part of the resilient member is a sealring 47 internally threaded to, screwupon the upper end of sleeve 48.The upper surface of resilientring 44 is beveled to abut thelower end ofbody 40.. The lower end of ring 44'.seats against seal ring'149 which inturn is internally ;,threaded and screwed upon the upper end ofsleeve-50.. .Seal'ring 51 is threaded. externally and threaded'toreceive' the upper. end of casing 11. The

ring 46 enclosing the upper end of the retainer'is flanged to supportspider 53 (Fig. 1b) which has a tapered upper opening to accommodateslips 54 used to grip the tubing whil'e itis being run in or out of thecasing.- During the fracturing operation there is attached to the upperend of the tubing, as shown at 55, in Fig.. la, a fittingconstructed toform a pressure-tight joint with the tubing and having connected theretoa universal hose connection 56. The tubing is supportedby means of ayoke 57 to which hook 58, cable 59' nnd cable connection 60 areattached, so the lowering and raising of the tubing may be effected bythe derrick draw works.

v The fractuiingiiuid is introduced to the tubing 17- under pressurefrom anyconveuient source not shown through pipe 61, pump 62, lines 63,64 and flexible tubing 6:3. Pressure gauge 66 isinterposed in the lineto show pres sures which exist. A valve 6'7 interposed in line 6-2 isoperable to divert the fluid from the tubing through pipe 68 into theannular space between the tubing and casing. When the fluid isintroduced in this fashion, valve as is open and pressures in line 68are determined by sure gauge se Granular materim' such as sand itsupasaness trolled by valves 79, 8t) and 81, respectively. Pressures in"these lines are recorded by 'gaugesvdb, 66c and'66d. Pipes 76, 77 and 78may function both as pressure or bleed lines. When functioning as thelatter, ipes 76a, 77a and 78a, controlled by valves 76b, 77b, and 78b,returnthe fluid to reservoir 71 and after bleeding off the pressure andmanipulating the valves in the respective lines the pressure fluid usedto operate the seals of the retainer maybe circulated back tothereservoir, by-passing any of the pressure lines 76, 77 and '78 asdesired.

In the fracturing operations herein contemplated, any suitable type ofhydraulic fluid may be used. Good results have been obtained with arelatively heavy oil having a sufiiciently low viscosity to facilitatepumpability. Such fluid as is considered by the operatorto-bebestadapted to the circumstances and conditions existing in the Wellshould be used, and if granular material such as sand is mixed with thefluid to support or prop the channels opened by fracturing, thecharacter and size of such granular substance is also the choice of theoperator.

Sixteen-mesh material has given good results and under screen andretained on a forty-mesh screen has proved satisfactory producingreadily permeable prop or spacing substance. in the instant process thenovelty resides primarily in the method of fracturing relatively narrowzones and movement of the seals or packers for isolating such zones inrapid sequence rather than in the selection of a-particular type offracturing fluid or sand.-

Explaining now the fracturing operations in the-apparatus justdescribed, after the well has been drilled and logged to locate thepermeable and impermeable formations, as wellas the suspectedoil-bearing sands, the casing is run with suitable abrading andcentering tools to clean the well bore preparatory to placing a cementcolumn After the casing hasbeen set and cemented, the well is shot atselected depths or levels where oil producing sands are suspected. Theshooting should penetrate both the casing and cement column andproduce'clean open shot holes from the casing into the formation topermit'a free unobstructed flow of fluid therethrough. The number aswell as the vertical and circumferential spacing of the shot holes iscritical to subsequent fracturing operations. If two-inch tubing is usedto supply the fracturing fluid, eight to twelve holes should be shot ineach fracturing zone in order to maintain a proper relationship betweenthe cross-sectional area of the tubing and the shot holes. This assuresthe high velocity necessary through the shot holes, preventing cloggingor obstruction of the ports and the accumulation of sand in the holesand annulus around the tubing between the packers often resulting insticking of the tubing and difficulties when the tubing and packers mustbe moved to the next fracturing zone.

1 An important feature of the instantfracturing operation is thereduction and limitation of the vertical depth of the zone to befractured. Heretofor-e, little or no regard has been given to the depthof this zone. Usually it is determined by the thickness of thepermeableformm tion. Experience has shown that this is an impropercriterion upon which to base the depth of the zone since thickness ofmore than to feet will normally give inditferentresults, depending uponthe depth of the well and normal conditions sand passing through atwenty-mesh:

- 10 to 20 feet, satisfactory fracturing of the formation is usuallyassuredvand adequate channeling obtained if the shot holes are withinthe zone and the sealing devices or packers are accurately placed.

With the casing properly perforated at the permeable formations, the gunperforator is removed from the well and the tubing is run with thepackers locatedon'the string as shown in Fig. 1c. .Assurning'the lowestforma- L on 15a in Fig. 1c is to be fractured andthat it has a thicknessof l0'to 20 feet, and the casing and cement column have been properlyperforated by holes 16, the tubing is now lowered until packers 18 arepositioned above and below the formation with the perforated tubingbetween the packers spanning the formation 15a;

Retainer 39 has been previously mounted upon the casing above thederrick floor and the fluid pressure system shown in Fig. 1b, as well asthe pressure fluid'supply hose have been connected up. Pressure fluid isnow introduced to the tubing 17 through hose 65 from pump 62, pipes 63and 64 with valve 67 open and valve '69 closed. As soon as the fluidpressure is applied to the tubing,

pistons 22 in the gripping sections of the packer 20 are forcedoutwardly, immobilizing the packers in position tween the packers fromthe well bore below the lower packer and the annulus between the tubingand easing above the upper packer. As the pressure is increased, thesealing members tighten against the casing and under the excessivepressures required for fracturing, the necessity of reinforcing theresilient sealing member 18, by coil springs 13a and sleeves 19can bereadily appreciated. This reinforcement reduces the tendency of theresilient material, usually rubber, to flow and aids in preventingfailure of the packers; Pressure upon the tubing'is increased until theformation is fractured, at which time there is a reduction in pressurecommensurate with the extent to which channels have been opened and thefluid permitted to expand. After fracturing, the reduced pres- I sure orwhat will be termed closed-in pressure is main:

tained in the tubing and formation by closing valve 67.

To release the packers preparatoryto moving them to the next fracturingzone which maybe above or below that just fractured, valve 6? is openedand pressure fluid supplied by pump 62 and pipe 68 to the annular spacebetween the tubing and casing above the upper packer. When this pressureequals or exceeds slightly the closedin pressure existing between the,packers and upon the fractured formation, tensionsprings 29, togetherwith the natural retractive force or tendency of resilient members 13will break the seals of the packers. Equalizing the pressure surroundingthe tubing with that in the tubing also causes pistons 22 to releasetheir grip upon the inside of the casing. I

When the packers have been released, the tubingis immediately shifted tothe next location to be fractured without delay for. pressure reductionin the system since the closed-in pressure is maintained by retainer 39at the well head. This is accomplished in spite of the dif ference indiameter of the tubing sections and the'couplings which jointhemtogether. The operation of the retainer can best be understood byreference to Figs.

lb and 2. While fracturing pressure is being imposed 3Z7 introducedthrough pipe'76 acting upon seal ring 47 constricts resilient annularmember 43, expanding it radially against the tubing. Fluid introducedthrough pipe 78 shifts ring 49 and sleeve 50 longitudinally, expandingresilient member 44 to form a seal with the exterior of the tubing andthat injected through pipe 77 between the seals serves to offset orequalize pressure built up in the casing and acting axially upon seal44; L.

' After fracturingand when the fracturing pressure has subsided toaclosed-in pressure to move the tubing to the next fracturing zonerequires only proper control of the flow of pressure fluid to theretainer. By valve manipulation theinjection and lay-passing ofthepressure fluid governs theexpansion and contraction of the seals 43and '44 in proper, sequence whereby a permanent seal is continuallymaintained at, the well head while permitting the passage of thecouplings through the seals as the tubing is shifted. It will beunderstood that the seal made by sealmembers 43 and l4 with the tubingwhen they are expanded thereagainst is of such nature that the tubingcan be moved therethrough without, how ever, permitting the esca'peoffluids through the seal. The release of the seals 43 and 44 is effectedby closing valves 79, 80 and 81 and opening valves in by-pass lines 76a,77a and 78a.

To follow the procedure which is used while shifting the tubing from onefracturing location to another with the tubing initially positioned inthe retainer as shown in Fig. 2 with seal member 44 expanded against thepipe and seal member 43 retracted to permit passage of back pressurevalve and coupling 33a, pressure fluid charged by pump 73 through pipe78 expands seal member 44 while that introduced through pipes 7'6 and 77is bypassed to the reservoir by manipulation of the valves in therespective lines. In this fashion, seal member 43 is retracted,permitting passage of coupling and back pres sure valve 331; throughseal member 43. As previously explained, pressure fluid is suppliedbetween the seals through pipe 77 only during fracturing operations whenboth sealmembers 43 and 44 are expanded. When the tubing has beenshifted longitudinally through seal 44 to the next coupling below,by-pass of pressurefluid through pipe 76a is discontinued bymanipulation of the valves and resilient member 43 is expanded to form aseal against the tubing while pressure fluid introduced through pipe 78is now by-passed to retract seal memher 44. The coupling below sealmember '44 can now be moved through the retracted seal while pressurefluid is charged through'pipe 76 to expand resilient member 43 forming apressure-tight seal against the tubing at the upper end of the retainer.Afiter passage of the coupling through 'member 44, it will. again beexpanded by introduction of pressure flnidthrough pipe 78 to form theseal against the tubing and the upper seal member 43 contracted to allowpassage of the coupling therethrough.

When the distances that the tubing must be moved requires removal oftubing sections because of the limitations imposed by the height of thederrick, back pressure valves as shown in Figs. 7 and 8 strategicallyinterposed in the tubing permit taking out sections of the tubing at thederrick floor without loss of pressure in the system. Before a sectionis removed, set screw 37 in the side of the back pressure valve isbacked off sufliciently to permit the ball valve 35 to seat and holdpressure on the system while fitting 55 with its hose connectiori 56 isshifted to a lower section. Upon coupling 'of the fitting 55 again tothe top of the tubing, set screw 37 is screwed in to unseat ball valve35 so pressure fluid can again be charged through the hose 65.

Itis contemplated that where single packers above and "below the zone tobe fractured do not span completely packers above and below those shownin Fig. 1c spaced at proper distances so an efiective seal will bemaintained. An example of the use of two packers above and below theformation to be fractured is shown in Figs. 10 and 11. Fig. 10 shows thelower portion of the tubing string while Fig. 11 shows a section of thestring immediately above that shown in Fig. 10 including the primarypacker below the formation 15 which is being "fractured Withthe twopackers13 above this formation. In these drawings the tubing is againindicated by'the numeral 17, the packers by the numeral 38', the pistontype slips which hold the packers in position in the casing by thenumerals 20. Packer operating devices are diagrammatically shown at 79andanti-extrusion devices are shown :at 80. A standing valve 81 at thebottom of I the string in Fig. 10 may be constructed to seat either upor down according to the desires of the operator. Under somecircumstances when circulating from the tubing to the space between thecasing and tubing the valve should seat up. If it is desired tocirculate from the space surrounding the tubing into the tubing, thevalve should seat down. r

In Fig. 11 the packers 18 above and below the formationd-d which is tobe fractured are operated or expanded to form a seal against the casing.The secondary packers 18, one shown between the operating device 7Q andanti-extrusion device in Fig. 10, the other below the anti-extrusiondevice 80 and above the operating device79 at the top in Fig. 11, areretracted since the formation 15 .to be fractured is relatively narrowand could be sealed ofi eflectively by the primary packers. Where bothprimary and secondary packers are necessary to efiectively seal theformation before fracturing, both primary and secondary packers will beexpanded in the manner that the primary packers are shown in Fig. 11.

In Figs. 17, l8, l9 and 20 is shown a modified type of pressure retainerwhich maintains a closed-in pressure while the packers are being shiftedin order to carry on a fracturing operation at a diflferent location.The operation of the device is similar to that shown in Fig. 2 sincepressure is applied to expand the lower packer or resilient seal member44 against the tubing until a coupling 33 or valve 33a arrives justbelow the sealing member. At this time the upper sealing member 43 isexpanded against the tubing and pressure is increased between thesealing members as explained in describing the operation of the retainershown in Fig. 2. The lower seal 44 is then retracted and the tubing isshifted longitudinally while a pressure-tight seal is held at the uppersealing member 43. Since the lower member 44 .has been retracted, thecoupling 33 easily passes therethrough and movement of the tubing isstopped just below the upper sealing member, At thistirne the lowersealing member is again expanded to form a seal about the tubing and theupper scaling member retracted to permit passage of the coupling orvalve, whichever is in position to be moved through the retracted seal43. The structure of the modified type of pressure retainer differs fromthat shown in Fig. 2 in that tapered segments 82 carried by springs 83and hung from rings 84 cooperate with backup rings 85 to preventextrusion of the resilient material alongthe tubing when high pressureis imposed to expand the sealing members and form a seal between thecasing and tubing. The spring attachment rings 84 are externallythreaded to be screwed into the threadedportions of sleeves 41 and 42.Adjusting rings $6 also are screwed into sleeves 41 and 42 and liebehind segments 82 to limit the upward movement of back-up rings 85.Behind the rings 86 in the sleeves 41 and 42 are holes 87 through whichthe rings may be adjusted by means of a drift pin. If the ring does notcover the hole, it may 'be necessary to have it plugged as shown at 88in the lower hole.

In Fig. 17 the lower sealing member 44 is expanded by fluidpres suresupplied through pipe 78. It will be I enemas g. ndted that the top edgeof the resilient member 44 is reinforced and confined by the lower.tapered surface of back-up ring 85 and the inwardly tapered surfaces 82aof segments 82. The outwardly tapered surfaces 82!) of these segmentsride along the inwardly tapered surface of the back-up ring. Alsoback-up ring 85 associated-with the lower resilient member 44 whenexpanded as shown in Fig. 17 is in abutment with the limiter ring 86.When the resilient member or seal is retracted as is member 43, theback-up ring is moved downwardly away from limiter ring 86 .withsegmentsSZ riding upon the upper part or" the taperedsurface of theback-up ring. When retracted, the surfaces 82;: present no obstructionand in fact facilitate passage of the couplings through the retractedseal.

sleeves ill and 42 andheld between the top of resilient elements 43 and4d and segments 82 of the respective packer restriction devices.Adjustment of limiter rings 36 will vary the internal diameter of theclosure segments toan extent and springs 83 upon which the seg ments arehung have. an. out'wardtension which spreads the segments when theresilient members have been retracted to permit passage of the tubecouplings. With the spreading of the segments back-up rings 85 willlikewise he moved longitudinally within the sleeves to the positionshown at the top of Fig. 17 where resilient element 3' is shown in aretracted position.

In Figs. l2, l3 and 14 is shown the circulating valve mechanismdiagrammatically indicated at 95 in Fig. 10.

Upon the tubing. below the slip 2b in Fig. are

' which has bearing relationship with valve sleeve 95. Be a tween thebearing portions of members 94 and 95 are rollers or balls to facilitaterotation of the valve sleeve;

In the mandrel 89 beneath the valve sleeve are ports 89a sealed byG-rings above and below the ports. Thelower .15 Back-up rings 85 arelongitudinally slidable within 861a rests upon shoulder 101a of thesleeve.

has attached to itsjlower end a gudgeon coupling shown in Figs. 2 1 and22. This coupling has centering lugs 98a. Abutting the lower end ofcoupling 97 and between the coupling and a shoulder on the mandrel area'plurality of secondary valve rings 99. Slidably mounted on the mandrelbelow the valve rings is a packer thimble 1%. At the upper end of thethimble is a tapered seat 100a and an annular space between the mandreland thimble which serves as a seat for the secondary valve rings 99.Surrounding the sleeve portion of the thimble is the resilient packer18. Below the packer thimble 100 and abutting its lower edge is a sleeve101 which has threeshoulders 161a, 10112 and 101C. The arming wedge Thelower end of the slip body 8012' sets against shoulder 101b and ashoulder formed in the slip actuating sleeve1tl2 abuts.

shoulder 1 .110 of the sleeve 101.

[As the tubing string is lowered into the well, the mechanism is in aretracted or locked position as shown in Fig. 21. The resilient packermember 18 is retracted and the primary and-secondary valves 97a and 99are raised from their seats in the packer thimble. The anti-extrusiondevice 80 is. in a retracted position and the serrated edged slips 103are likewise retracted against the tapered sides of the slip body 80b.The slot in the lockinghead 102a at the end of the slip actuating sleeve102 is in engagement with pm 104 extending radially from the gudgeoncoupling. While the mechanism is being lowered-into the well, fluid isfree to circulate either upwardly. or downwardly about the exterior ofthe packer, the anti-extrusion device and throughout the length firmlyagainst longitudinal or rotative movement with respect to movementof'the mandrel. An assembly ring 105 (Fig. 22) attachedto the undersideof actuating sleeve 102 limits the upward movement of the actuating endof the valve sleeve is routed-out to form a skirting 7 95a surroundingthe mandrel and a discharge annulus 96 between the skirting and mandrel.Since the bowed wrenching springs 92 have frictional engagement with thea casing, when it is desired to circulate from the tubing to the annularspace. surrounding the tubing or from the annular space into the tubing,mandrel 89 is rotated on its axis to screw'the threaded joint betweenthe spring cylinder 91'and'sleeve 90 which raises orlowcrs the valvesleeve 95 to cover or'uncover ports 89a according to the movement of thevalve sleeve. in Figs. 12 and 13 the valve is shown closed. Upwardmovement of the valve sleeve 95 resulting from rotation of the mandrelwithin the spring shell will bring ports 89a into the discharge annulus96 beneath skirting 95, at which time fluid may be discharged from the.tubing or circulated into the tubing. Rotation of the mandrel in theopposite direction will lower the valve sleeve to. seal off the ports inthe mandrel and prevent further circulation to or from the tubing.

In Figs. 21, 22 and 23 is shown ,a modified type of packer arming deviceand slips for positioning the tubing in the casing. in conjunction withthe packer is an antiextrusion device 8% which is detailed in Figs. Hand16.

' Also connected into the coupling from below is 'a mandrel 89which'serves as a mounting for the mechanism and -wall of the casing toform a pressure-tight seal.

sleeve by abutment with the lower end of sleeve 191 while downwardmovement of the actuating sleeve is limited by abutment of the shoulderof the actuating sleeve with shoulder 1010 as previously noted. Afterunlocking the mandrel, it may be lowered until. the

196 to the upper ends of links 107. The lower ends of the links areattached to the slip actuating sleeve 102. Since the actuating sleeve102 is held against movement within the casing by springs 92 as thetapered end of the slip body b expands slips- 103, they will firmly gripthe inner wall of the casing and hold the mechanism rigidly in place. ia

With the slips set in the manner described, continued downward movementof the mandrel causes valve 97:: in coupling 97 to seat in the top ofthe packer thimble and expand the resilient'packer 18 against the insideSince valve rings 99 new seat in the annulus in the top of the packerthimble, the fluid passageways both outside of the thimble and inside ofthe thimble are effectively closed. To prevent extrusion of theresilient material winch forms theresilient packer 18 due to thehighpressure imposed from above, there is provided below the packers ananti-extrusion device 80 detailed in Figs. 15 and 16. The upper armingwedge 80a of this device, as previously noted, abuts shoulder 101a ofsleeve 101 and surrounds the upper part of the sleeve as shown in Fig.22. The

11 top of the arming wed'ge supports the lower end of the packer andwhen the packer thirnble is forced downwardly upon lowering of themandrel, the packer is squeezed and expanded between the packer thimbleand the top of by a guide tongue 80b which passes through the space.

between the ends of the sleeve and registers with a slot 80:: in theslip body. A tapered surface 8% at the top of the arming wedge and asimilar surface fitlg tapered in a reverse direction spread theexpansion sleevewhen the packer is expanded so that the top edge of thesleeve supplements the top of the arming wedge to forma backing surfaceand prevent extrusion of the resilient material through the annularspace between the arming wedge and casing. Ports 80h are provided in theslip body j as shown in Figs. 21 and 22 to facilitatedischarge of fluidcirculating between the mandrel S9 and sleeve 1.01, while the mechanismis locked or when going into the hole. To move the packer and disengagethe slips to return the mechanism to a locked position, the tubing isgradually raised to unseat the primary valve on coupling 97 from thepacker thimble. The secondary valve rings remain inthe annular spacebetween the thimble and mandrel preventing'a rapid rush of abrasivefluid through the valve and rapid deterioration of the valve seats. Asthe mandrel is moved upwardly, packer 18 will be retracted and the slipslflli disengaged from the casing wall.. When :the'a-ssembly ring 105abuts thelower end of sleeve 101,

the locking head 102a is in a position to be rotated into engagementwith pin 104-. anti-disassembly locking screw 109: (Fig. 21) in the endof the guide tongue 80d prevents complete disengagement of the armingwedge and slip body.

Thus, it will be seen that there has been provided a process by whichfracturing'operations may be conducted without the delay now necessaryafter each operation to permit reduction of pressure upon the system.Also there is provided a process which entirely eliminates thedifficulties encountered by backflow of pressure fluid and sand.Limiting f the fracturing zones to narrow thickness and maintaining aproper relationship between tubing cross-sectional area and the area ofthe shot holes in each zone assures effective fracturing and renarrowzones, the process would be wholly uneconomical if operations wereinterrupted after each. fracturing to await the necessary time forpressure reduction on the system before subsequent fracturing operationswere performed. This waiting time is' the normal procedure in order thatthe pressure maintained. on the formation can be dispersed so thatequipment, including packers and tubing, can be shifted to the nextzone. Unlessv the pressure is permitted to reduce, it isimpossible toprevent backflow of liquid and sand to the surface, which circumstancesare hazardous to the operator and dangerous because of the highpressures being used. If, however, the packers or sealing devices can beshifted while pressure is maintainedon the system and without delayingthe operations by the waiting periods, fracturing can .bec'ornpleted inamuchshorter period of time and more 12 effectively since thepossibility of sand packing is substantially eliminated. I Thin zonefracturing hereinbefore described is advantageous in that it effectivelyfractures a greater amount of formation during each fracturing operationthan previous fracturing methods where relatively thick zones arefractured. Also, thin zone fracturing limits to a great extent verticalfracturing of the formation which introduces the difliculties ofvertical migration of fluids permitting the ingress of objectionablecontaminants such as Water and gas to the producing sands.

Also there has been provided an proved type of circulating valve andactuating mechanism for functioning said valves. To prevent extrusion ofthe resilient material used in the packers around the ends'of thereinforcement elements used withthe packers, there has been providednovel anti-extrusion devices. These mechanisms are adapted to greatlyfacilitate shifting of the tube ing from formation to formation duringfracturing operations without materiallyi reducing closed-in pressure ofthe well and eliminate to a great extent trouble and difiicultiesencountered "with packers sticking the tubing in the casing.

7 Having thus described my invention, I claim:

1. In a method for completing a well wherein acasing is set in a wellbore having a plurality of hydrocarbon productive zones and the casingis perforated in more than one of said zones, the steps of inserting atubing in said casing, sealing oflt the annulus between said tubing andsaid casing aboveand below the perforations at a first one of saidzones, introducing fluid through said tubing into'said sealed offportion of the annulus and imposing suflicient pressure thereon tofracture said first zone, closing saidtubing following fracturing tomaintain pressure within the tubing and in said fractured Zone,introducing fluid into said annulus above and below the sealed offportion of the annulus and imposing suflicient pressure thereon tosubstantially equalize the pressures within and above and below saidsealed off portion of the an nulus, manipulating the tubing verticallywhile sealing against pressure escape at the top of the annulus, sealingofl the annulus between said tubing and casing above and below theperforations at a second one of said zones,

' and reinstituting fluid flow through said tubing at a pressuresufiicient to-fracturesaid second zone.

2. In a method as in claim 1 and where the tubing is provided withspaced couplings of greater diameter than the. tubing, the step whereinthe sealing of the annulus at the top thereof during verticalmanipulation of the tubing is accomplished by successively shifting theseal to opposite'sides of the couplings as the couplings reach and movepast the top of the annulus.

. 3..In a method as in claim 2, the step of removing sections of tubingas they move'upwardly past the an nulus and closing off the tubing toflow therethrough immediately below the sections to be removed prior tore .moval thereof.

4. Apparatus for fracturing a well having a plurality ofspacedhydrocarbon productive zones, the well being lined with a casingperforated at the respective productive zones, comprising a tubinginserted in the casing, a

pair of vertically spaced packers'on the tubing, ports in the tubingbetween the packers, means for introducing fracturing fluid into thetubing and out through said ports,

mechanism connected with said packers and operable upon the creation ofa pressure differential between the space between the packers and aboveandbelow the packers toset the packers against the inside of the ing andupon substantial equalization of the pressure in the space betweenthepackers and above and below same to release the packers, means forequalizing said pressures following fracturing to release said packers,mechanism for manipulating the tubing vertically in the well to shiftsaid packers from one zone to another when the packers are released,. apressure retainer sealing the top 13 of the annulus between the tubingand casing as the tubing is manipulated, and means operable to preventloss of pressure through the tubing whereby a closed-in pressure iscontinuously maintained in the annulus between the casing and tubingduring the successive fracturing of the plurality of zones.

5. Apparatus as in claim 4 wherein said pressure retainer includeshydraulically actuated vertically spaced seals operable alternately toseal against axially spaced portions of the tubing to permit passage oftube couplings during manipulation without loss of pressure.

6. Apparatus as in claim 4 wherein the tubing is in coupled sections,the sections being provided with back pressure valves operable to closeoff flow toward the'surface so that a section above can be removedwithout loss of pressure as the tubing is moved upwardly in the well.

References Cited in the file of this patent UNITED STATES PATENTS Re.23,733 Farris Nov. 10, 1953 r 14 Hansen Dec. 2, Minor Ian. 24, Erwin etal. Nov. 3, Ragan Apr. 9, Benckenstein July 25, Baker Mar. 6, Conrad eta1. a. July 8, Page July 15, Warren Sept. 9, Clark June 16, LynesIune30, Dismukes Jan. 11, Brown Sept. 11, Reistle Nov. 6, Reistle Feb.26, Baker et a1 Sept. 17,

